A study of capillary pressure and capillary continuity in fractured rocks

The production of oil is challenging in fractured reservoirs due to the large transmissibility contrast between matrix and fracture, and primary recovery is often low. The recovery efficiency depends on the relationship between the fracture and matrix permeabilities, and is strongly dependent on the wettability of the matrix, which reflects the imbibition potential of the reservoir. High demands and rising oil prices has increased focus on improved oil recovery from large, low recovery oil fields. Some of the world’s largest remaining oil reserves are found in oil‐wet, fractured, carbonate reservoirs. The understanding of multiphase fluid flow in oilwet fractured reservoirs has been studied in this thesis, especially the influence of capillary pressure. The presence of capillary pressure is important in recovery mechanisms like spontaneous imbibition, waterflooding and gravity drainage. The centrifuge method is a frequently used method to measure capillary pressure, and relies on establishing a stable saturation for each rotational speed. There exists no global, absolute requirement for equilibrium, and this size is often based on experience, and is strongly dependent on the sensitivity of the measuring apparatus. The benefits of using an automated, high resolution camera in volume measurements have been demonstrated, and the impact of accuracy on the time to reach equilibrium saturation at a given rotational speed is illustrated. Another difficulty when generating the capillary pressure curve using a centrifuge is the large uncertainty related to solving the integral problem associated with the calculation of the capillary pressure curve from production data. Methodologies for direct measurement of saturation to avoid this uncertainty have been proposed, eliminating the need for mathematical approximate solutions to obtain the local capillary pressure curve. The Nuclear Tracer Imaging Centrifuge (NTIC) method has the capability to measure the local water saturation during centrifugation, thus limiting the redistribution of fluids and the need to solidify phases, drawbacks associated with other methods for direct measurement of capillary pressure. Improved capillary pressure curves are presented, and the reliability and reproducibility in the NTIC capillary pressure curves have been demonstrated. The curves generally coincided with results from other existing centrifuge methods. The correct measurement of saturation as a function of capillary pressure will increase the confidence in simulations where the input multiphase controls the flow patterns and the recovery. The impact of wettability on capillary continuity in fractured rocks has been studied extensively, but is still not fully understood. Two visualization methods, to measure the in situ fluid saturation development in fractured rocks, are reviewed and illustrate the benefits of applying complimentary imaging to study the impact of fractures and wettability on multiphase flow in fractured reservoirs. Separately, each technique provided useful insights to local phenomena, but collectively, when combining the resolutions and observations made, a better explanation of observed phenomena could be obtained. The concept of wetting phase bridges observed during waterfloods in stacked waterwet homogenous chalk plugs has been extended to a heterogeneous limestone rock type with an oil‐wet wetting preference. The study shows how droplets of oil forming on the fracture surface contribute to the fluid transfer between two separated matrix blocks across an open fracture. The presence of droplets, evolving into bridges across the fracture, may be important for gravity drainage, reducing the capillary retained oil in each isolated matrix block. Droplets growth is impacted by the wettability of the interface between fracture and matrix and flow rates. Spontaneous transport of oil, i.e. transport without associated pressure increase, across the fracture was observed when there was an affinity between mobile fluid and the wettability of the fracture surface. Injection rates and pressure across the fracture controlled droplet growth and the potential for the droplets to bridge the fracture to form a continuum in the capillary pressure curve. The importance of fracture capillary pressure in waterfloods of fractured limestone rocks was demonstrated in a numerical reproduction of experimental results. The results showed not only that there was a dependency of the presence of capillary pressure in the fracture, but also there was a strong dependency of the distribution of the capillary pressure inside the fracture network on the development of waterfronts during water injection

New Insight from Visualization of Mobility Control for Enhanced Oil Recovery Using Polymer Gels and Foams

Several enhanced oil recovery (EOR) methods have been designed and developed in the past decades to maintain economic production from mature reservoirs with declining production rates. This chapter discuss mitigation of poor sweep efficiency in layered or naturally fractured reservoirs. EOR methods designed for such reservoirs all aim to reduce flow through highly conductive pathways and delay early breakthrough in production wells. Two approaches within this EOR class, injection of foam and polymer, specifically aim to improve the mobility ratio between the injected EOR fluid and the reservoir crude oil. Reduction in fracture conductivity may be achieved by adding a crosslinking agent to a polymer solution to create polymer gel. This may also be combined with water or chemical chasefloods (e.g. foam) for integrated enhanced oil recovery (iEOR). Polymer gel and foam mobility control for use in fractured reservoirs are discussed in this chapter, and new knowledge from experimental work is presented. The experiments emphasized visualization and in situ imaging techniques: CT, MRI and PET. New insight to dynamic behaviour and local variations in fluid saturations during injections was achieved through the use of complementary visualization techniques

Pore-scale dynamics for underground porous media hydrogen storage

Underground hydrogen storage (UHS) has been launched as a catalyst to the low-carbon energy transitions. The limited understanding of the subsurface processes is a major obstacle for rapid and widespread UHS implementation. We use microfluidics to experimentally describe pore-scale multiphase hydrogen flow in an aquifer storage scenario. In a series of drainage-imbibition experiments we report the effect of capillary number on hydrogen saturations, displacement/trapping mechanisms, dissolution kinetics and contact angle hysteresis. We find that the hydrogen saturation after injection (drainage) increases with increasing capillary number. During hydrogen withdrawal (imbibition) two distinct mechanisms control the displacement and residual trapping – I1 and I2 imbibition mechanisms, respectively. Local hydrogen dissolution kinetics show dependency on injection rate and hydrogen cluster size. Dissolved global hydrogen concentration corresponds up to 28% of reported hydrogen solubility, indicating pore-scale non-equilibrium dissolution. Contact angles show hysteresis and vary between 17 and 56° Our results provide key UHS experimental data to improve understanding of hydrogen multiphase flow behaviour.publishedVersio

Hydrogen Relative Permeability Hysteresis in Underground Storage

Implementation of the hydrogen economy for emission reduction will require storage facilities, and underground hydrogen storage (UHS) in porous media offers a readily available large-scale option. Lack of studies on multiphase hydrogen flow in porous media is one of the several barriers for accurate predictions of UHS. This paper reports, for the first time, measurements of hysteresis in hydrogen-water relative permeability in a sandstone core under shallow storage conditions. We use the steady state technique to measure primary drainage, imbibition and secondary drainage relative permeabilities, and extend laboratory measurements with numerical history matching and capillary pressure measurements to cover the whole mobile saturation range. We observe that gas and water relative permeabilities show strong hysteresis, and nitrogen as substitute for hydrogen in laboratory assessments should be used with care. Our results serve as calibrated input to field scale numerical modeling of hydrogen injection and withdrawal processes during porous media UHS.publishedVersio

A Pore-Level Study of Dense-Phase CO2 Foam Stability in the Presence of Oil

The ability of foam to reduce CO2 mobility in CO2 sequestration and CO2 enhanced oil recovery processes relies on maintaining foam stability in the reservoir. Foams can destabilize in the presence of oil due to mechanisms impacting individual lamellae. Few attempts have been made to measure the stability of CO2 foams in the presence of oil in a realistic pore network at reservoir pressure. Utilizing lab-on-a-chip technology, the pore-level stability of dense-phase CO2 foam in the presence of a miscible and an immiscible oil was investigated. A secondary objective was to determine the impact of increasing surfactant concentration and nanoparticles on foam stability. In the absence of oil, all surfactant-based foaming solutions generated fine-textured and strong foam that was less stable both when increasing surfactant concentrations and when adding nanoparticles. Ostwald ripening was the primary destabilization mechanism both in the absence of oil and in the presence of immiscible oil. Moreover, foam was less stable in the presence of miscible oil, compared to immiscible oil, where the primary destabilization mechanism was lamellae rupture. Overall, direct pore-scale observations of dense-phase CO2 foam in realistic pore network revealed foam destabilization mechanisms at high-pressure conditions.publishedVersio

Microfluidic hydrogen storage capacity and residual trapping during cyclic injections: Implications for underground storage

Long-term and large-scale H2 storage is vital for a sustainable H2 economy. Research in underground H2 storage (UHS) in porous media is emerging, but the understanding of H2 reconnection and recovery mechanisms under cyclic loading is not yet adequate. This paper reports a qualitative and quantitative investigation of H2 reconnection and recovery mechanisms in repeated injection-withdrawal cycles. Here we use microfluidics to experimentally investigate up to 5 cycles of H2 injection and withdrawal under a range of injection rates at shallow reservoir storage conditions. We find that H2 storage capacities increase with increasing injection rate and range between ∼10% and 60%. The residual H2 saturation is in the same range between cycles (30–40%), but its distribution in the pore space visually appears to be hysteretic. In most cases, the residually trapped H2 reconnects in the subsequent injection cycle, predominantly in proximity to the large pore clusters. Our results provide valuable experimental data to advance the understanding of multiple H2 injection cycles in UHS schemes.publishedVersio

Unlocking multimodal PET-MR synergies for geoscience

The recent combination of positron emission tomography (PET) and magnetic resonance (MR) imaging modalities in one clinical diagnostic tool represents a scientific advancement with high potential impact in geoscientific research; by enabling simultaneous and explicit quantification of up to three distinct fluids in the same porous system. Decoupled information from PET-MR imaging was used here, for the first time, to quantify spatial and temporal porous media fluid flow. Three-dimensional fluid distribution was quantified simultaneously and independently by each imaging modality, and fluid phases were correlated with high reproducibility between modalities and repetitive fluid injections.publishedVersio

Pore-level Ostwald ripening of CO2 foams at reservoir pressure

The success of foam to reduce CO2 mobility in CO2 enhanced oil recovery and CO2 storage operations depends on foam stability in the reservoir. Foams are thermodynamically unstable, and factors such as surfactant adsorption, the presence of oil, and harsh reservoir conditions can cause the foam to destabilize. Pore-level foam coarsening and anti-coarsening mechanisms are not, however, fully understood and characterized at reservoir pressure. Using lab-on-a-chip technology, we probe dense (liquid) phase CO2 foam stability and the impact of Ostwald ripening at 100 bars using dynamic pore-scale observations. Three types of pore-level coarsening were observed: (1) large bubbles growing at the expense of small bubbles, at high aqueous phase saturations, unrestricted by the grains; (2) large bubbles growing at the expense of small bubbles, at low aqueous phase saturation, restricted by the grains; and (3) equilibration of plateau borders. Type 3 coarsening led to stable CO2 foam states eight times faster than type 2 and ten times faster than type 1. Anti-coarsening where CO2 diffused from a large bubble to a small bubble was also observed. The experimental results also compared stabilities of CO2 foam generated with hybrid nanoparticle–surfactant solution to CO2 foam stabilized by only surfactant or nanoparticles. Doubling the surfactant concentration from 2500 to 5000 ppm and adding 1500 ppm of nanoparticles to the 2500 ppm surfactant-based solution resulted in stronger foam, which resisted Ostwald ripening. Dynamic pore-scale observations of dense phase CO2 foam revealed gas diffusion from small, high-curvature bubbles to large, low-curvature bubbles and that the overall curvature of the bubbles decreased with time. Overall, this study provides in situ quantification of CO2 foam strength and stability dynamics at high-pressure conditions.publishedVersio

Multi-scale dissolution dynamics for carbon sequestration in carbonate rock samples

Carbon dioxide (CO2) sequestration in porous, sedimentary reservoirs is a key technology to mitigate emissions of anthropogenic CO2 and curb irreversible climate change. The abundance of carbonate formations, both as saline aquifers and hydrocarbon reservoirs, makes future CO2 storage in carbonate formations highly likely. The weak carbonic acid that forms when CO2 dissolves in water will, however, interact with highly reactive carbonate. Preferential flow paths may form during dissolution or calcite precipitation may reduce injectivity - both processes significantly impacting reservoir sweep efficiency. Hence, understanding the dynamics of the dissolution processes and their influence on flow properties is necessary to safely store CO2 in carbonate formations. Darcy and sub-Darcy scale dissolution kinetics were here assessed in carbonate core plugs with and without pre-existing highly permeable pathways, during multiphase flow and under relevant storage conditions. Darcy-scale dissolution and precipitation data (injectivity changes, effluent analysis and mass loss) confirmed that CO2 and brine co-injections altered the carbonate rock structure on Darcy scale, but could not determine the cause of change. Multi-modal imaging was applied to independently quantify structural changes with computed tomography (CT) and aqueous flow characteristics with positron emission tomography (PET), thereby determining injectivity dependence on local flow patterns. Formation of high permeability pathways, which was expected due to rock dissolution, was only observed in cores with pre-existing open fractures, where reactive flow was limited to the fracture plane. A good correlation between the two imaging modules was found: areas of higher porosity yielded a low-density CT signal (i.e. high number of voids present) and a high PET signal density (i.e. large volume of traced fluid present). Loss of injectivity suggested local changes in the flow pattern due to blocking of pore throats by moving particles or secondary precipitation or mineralization of dissolved ions. High-resolution PET imaging revealed cementation, that was also visible using micro-CT, hence determining sub-Darcy local flow obstructions that led to decreased Darcy scale injectivity. Multi-modal imaging, where core characteristics, such as large vugs and cementation, can be independently determined by complementary modalities, may therefore be a useful tool to quantify reactive flow and resulting dissolution in rock samples.publishedVersio